Sign up to receive free email alerts when patent applications with chosen keywords are publishedSIGN UP

Abstract:

Systems and methods for oil recovery from oil shale are described.
Systems and methods may include a method for in-situ conversion of oil
shale. The method may include providing one or more magnetic probes
within an oil shale formation; providing magnetic nanoparticles into the
oils shale formation; and alternating the magnetic field of the one or
more magnetic probes to heat the oil shale formation. A system for
in-situ conversion of oil shale may include one or more magnetic probes
within an oil shale formation and magnetic nanoparticles within the oils
shale formation. A magnetic field may be applied by the one or more
magnetic probes to the magnetic nanoparticles to heat the oil shale
formation. A composition for a fracture fluid may include a fracturing
fluid and magnetic nanoparticles.

Claims:

1. A method for in-situ conversion of oil shale, the method comprising:
providing one or more magnetic probes within an oil shale formation;
providing magnetic nanoparticles into the oils shale formation; and
alternating the magnetic field of the one or more magnetic probes to heat
the oil shale formation via the magnetic nanoparticles.

7. The method of claim 1, wherein the magnetic nanoparticles are provided
with a fracture fluid.

8. The method of claim 7, wherein the magnetic nanoparticles are provided
at a concentration of approximately 0.2 lb/bbl to approximately 50 lb/bbl
in the fracture fluid.

9. The method of claim 1, wherein the magnetic field is alternated at a
rate of approximately 50 kHz to approximately 10 MHz.

10. The method of claim 1, wherein the magnetic field has a strength of
approximately 10 mT to approximately 250 mT.

11. The method of claim 1, wherein the temperature of the oil shale
formation is increased by approximately -200.degree. F. to approximately
600.degree. F.

12. The method of claim 1, wherein the process is operated for
approximately 2 years to approximately 7 years.

13. The method of claim 1, wherein the method produces bitumen and
lighter oil, and the bitumen and lighter oil is produced by conventional
production methods.

14. A system for in-situ conversion of oil shale, the system comprising:
one or more magnetic probes within an oil shale formation; magnetic
nanoparticles within the oils shale formation; and wherein a magnetic
field is applied by the one or more magnetic probes to the magnetic
nanoparticles to heat the oil shale formation.

15. The method of claim 14, wherein the one or more magnetic probes are
spaced at a distance of approximately 2 m to approximately 6 m.

16. The method of claim 1, wherein the one or more magnetic probes are
oriented parallel or perpendicular to the wellbore.

17. The system of claim 14, wherein the magnetic field is alternated at a
rate of approximately 50 kHz to approximately 10 MHz, and has a strength
of approximately 10 mT to approximately 250 mT.

19. The system of claim 14, wherein the magnetic nanoparticles are
provided with a fracture fluid.

20. The system of claim 19, wherein the magnetic nanoparticles are
provided at a concentration of approximately 0.2 lb/bbl to approximately
50 lb/bbl in the fracture fluid.

Description:

FIELD

[0001] The present disclosure relates to systems and methods for
processing hydrocarbons, and, more specifically, to systems and methods
for in-situ or similar conversion of hydrocarbons, such as oil shale.

BACKGROUND

[0002] Shale is considered a significant alternative source of oil, but
the cost of extraction is typically higher than other oil sources. As the
price of oil increases, extraction of oil from shale will become more
economically viable.

[0003] World total shale oil reserves are estimated at approximately 2,826
billion barrels. About 52% (approximately 1,446 billion barrels) of that
total world shale oil reserves are located in the Green River Formation.
This is more than three times Saudi Arabia's proven oil reserves. The
Green River Formation is located across Colorado, Utah and Wisconsin in
the United States of America, and is considered one of the largest known
oil shale formations in the world.

[0004] Hydrocarbons in the Green River Formation are mainly kerogen, which
cannot be economically extracted using conventional technology.
Commercial oil production has been attempted in the Green River Formation
for the last 100 years, especially during periods of higher oil prices.
In one process, an in-situ conversion process (ICP) cracks kerogen into
lighter oils using tightly spaced electric heaters that heat the
formation for long periods of time, typically about 3-6 years. This
process, however, is not commercially viable due to high costs of
operation and extraction.

BRIEF DESCRIPTION OF THE DRAWINGS

[0005] The accompanying drawings, which are included to provide a further
understanding of the disclosure and are incorporated in and constitute a
part of this specification, illustrate preferred embodiments of the
disclosure and together with the detailed description serve to explain
the principles of the disclosure. In the drawings:

[0006] FIG. 1 is a schematic diagram of an exemplary in-situ conversion
process using magnetic nanoparticles and alternating magnetic fields.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0007] Systems and methods are described for extraction of oil from shale
formation. In certain embodiments, processes may be used to extract oil
from Green River Formation shale or other shale formations that have
large concentrations of heavier hydrocarbons, such as kerogen, by
cracking them in-situ into lighter hydrocarbons prior to extraction. In
certain embodiments, the systems and methods described herein may be used
for recovery of heavy oil by decreasing viscosity to a lower recoverable
viscosity. The examples described herein relate to the Green River
Formation for illustrative purposes only. In particular, the systems and
methods may be used wherever cracking of heavier hydrocarbons is
desirable. Embodiments may be used with, for example, tar sands as well.
Lower nanoparticle concentration and/or lower magnetic field may be used
in such applications as lower heat is generally needed to decrease the
density of heavy oil, compared to the heat needed for cracking. Any oil
and gas production enhancement facility and/or transportation system
where viscosity reduction may benefit from use of the embodiments
described herein. Embodiments may allow for improved pumping, spreading,
chemical synthesis reactions to produce higher value intermediaries
and/or end products. Embodiments may be used in any type of subsurface
application that requires heat, or for non-underground uses, such as
heating of reactor vessels, where appropriate.

[0008] As disclosed in exemplary embodiments herein, magnetic
nanoparticles may be utilized to generate heat for long time periods,
which may in turn generate hydrocarbons by in-situ conversion process
(ICP) technology. Magnetic nanoparticles may be incorporated into
fracture fluids and injected into a formation, such as a shale formation.
In certain embodiments, the magnetic nanoparticles may be added to
fracture fluid formulations and delivered into target zones, such as a
kerogen zone, through fractures or existing pores. The downhole
contacting of the fracture fluids with the subterranean formation can be
any suitable contacting. In some examples, the contacting can include
contacting subterranean material that is in or proximate to a production
zone. In some examples, the method of treating the subterranean formation
may be a method of fracking, depositing proppant, curing resin, or any
combination thereof.

[0009] FIG. 1 is a schematic diagram of an exemplary in-situ conversion
process using magnetic nanoparticles and alternating magnetic field. One
or more magnetic probes (A and B) may be positioned within a formation.
The one or more magnetic probes may be located in a wellbore and/or at
different depths. The one or more magnetic probes may be spaced at a
distance of approximately 2 m to approximately 6 m, more preferably 3 m
to approximately 5 m. The one or more magnetic probes may be oriented
relative to the wellbore in parallel and/or perpendicular directions. In
certain embodiments, the one or more magnetic probes may be oriented
relative to the wellbore in an oblique direction and/or a non-linear
orientation. The one or more magnetic probes may be oriented relative to
one another in parallel directions. In certain embodiments, however, the
one or more magnetic probes may be oriented relative to one another in
perpendicular, oblique and/or in a non-linear orientation. Magnetic field
may be generated between magnetic probes that have been placed inside a
main wellbore and/or inside one or more multi-lateral wellbores extending
from the main wellbore. The timing and patterns of activation may vary.
In general, having all probes active at the same time may generate more
heat, which may help to improve the efficiency of the in-situ conversion
process.

[0010] A fracture fluid containing magnetic nanoparticles may be provided
to the formation. The magnetic nanoparticles may be provided to the
formation as a compacted pill or pressed tablet. In certain embodiments,
the magnetic nanoparticles may be dry blended with proppants or
precipitated from solution into solid deposits by a pH and/or chemical
additive and/or surfactant in a secondary addition to the fracturing
fluid during pumping or downhole. Alternatively, magnetic nanoparticles
may be coated onto the proppant and placed inside the fractures located
within a subterranean formation as part of the hydraulic fracturing
treatment.

Magnetorheological Fluids

[0011] Magnetorheological (MR) fluids are fluids that change apparent
viscosity in response to a magnetic field. MR fluids may include a
suspension of magnetizable particles in a carrier liquid or fluid. In
some examples, the MR fluid can go from the consistency of a liquid to
that of a solid, semi-solid, or gel with a response time on the order of
milliseconds. In some examples, the magnetizable particles and the
carrier liquid can be any substantially magnetizable particles and
carrier liquid, such that the fluid exhibits a change in apparent
viscosity or yield shear strength in response to an electric field. The
MR fluid can include any suitable additional material. In some examples,
the MR fluid may include anti-settling agents that aid in keeping the
magnetizable particles suspended in the carrier liquid, such as
thixotropic agents, surfactants, dispersants, thickeners, rheology
modifiers, or anti-wear agents.

[0012] In various examples, the magnetizable particles can include any
magnetizable solid material, such as paramagnetic, superparamagnetic,
ferrimagnetic, and ferromagnetic materials. Examples of magnetizable
materials may include pure metals, metal alloys, metal compounds, and any
magnetically soft material. Additional examples of magnetizable materials
can include iron; nickel; cobalt; alloys of Fe, Ni, or Co; iron oxide;
gamma iron oxide; iron cobalt alloys, iron nickel alloys, iron silicon
alloys, iron carbide, steel of carbon content lower than 1%, alloys of
iron with aluminum, silicon, cobalt, nickel, vanadium, molybdenum,
chromium, tungsten and manganesevarious ferrites, including ferrites of
Co, Fe, Mg, Mn, Ni or Zn, or combinations thereof, manganese zinc
ferrites and zinc nickel ferrites; chrome oxide, iron nitride; vanadium
alloys, tungsten alloys, copper alloys, manganese alloys; magnetic oxides
of chromium and iron, such as chromium dioxide, gamma-Fe2O3 and
Fe3O4; any other suitable magnetizable material; and
combinations thereof. In various examples, the magnetizable particles can
have an average diameter of about 0.001-10,000 μm, 0.01-1000 μm,
0.1-100 μm, and/or about 1-20 μm. In various examples, the size
distribution of the magnetizable particles can be monomodal; in other
examples, the size distribution of the magnetizable particles can be
bimodal or polymodal, with each average diameter of each grouping of
particle sizes being between about 0.001-10,000 μm and being present
in any suitable proportion. In various embodiments, the magnetizable
particles can be about 0.1-99.9 wt %, 10-95 wt %, 25-90 wt %, or about
50-90 wt % of the MR fluid.

[0013] In various examples, the carrier liquid can be a mineral oil, a
hydrocarbon oil, water, a silicone oil, an esterified fatty acid, an
organic liquid, a solvent, or a combination thereof. In some examples,
the carrier liquid can have a viscosity of about 0.01 to 100,000 cP, 0.1
to 10,000 cP, 1 to 1000 cP, or about 10 to 200 cP, measured at about room
temperature. In some examples, the MR fluid with no exposure to a
magnetic field can have a viscosity substantially the same as the
viscosity of the magnetically insulating fluid. In some examples, the
carrier liquid can be about 0.1-99.9 wt %, 0.5-80 wt %, 1-50 wt %, 10-50
wt %, or about 1-20 wt % of the MR fluid.

[0014] In some examples, the MR fluid can include a surfactant to aid in
keeping the magnetizable particles suspended in the carrier liquid. The
surfactant can be any suitable surfactant, for example, oleic acid,
tetramethylammonium hydroxide, citric acid, soy lecithin, or a
combination thereof. In some examples, at least some of the magnetizable
particles can be coated by surfactant. The surfactant can be present in
any suitable amount, such as less than about 1 wt % of the MR fluid, or
less than about 0.1 wt % of the MR fluid.

[0015] In some examples, the MR fluid can include a thixotropic agent to
aid in keeping the magnetizable particles suspended in the carrier
liquid. In some examples, the thixotropic agent is fumed or precipitated
silica. The thixotropic agent can be present in any suitable amount, such
as less than about 10 wt % of the MR fluid, less than about 1 wt %, or
less than about 0.1 wt % of the MR fluid.

[0016] In some examples, the MR fluid can further include suspended
particles of an organic polymeric material that can enhance the MR
properties of the MR fluid, such as a polymerized alkene-containing
compound such as polystyrene. In some examples, the suspended particles
of organic polymeric material can have an average diameter of about
0.01-1000 μm, or about 1-500 μm. In some examples, the MR fluid can
include about 1-75 wt %, 5-50 wt %, or about 5-30 wt % of the suspended
particles of the organic material.

[0017] In various examples, the MR fluid can experience a change in yield
shear strength upon exposure to a magnetic field of about 0.01
kA/m-100,000 kA/m, 0.1 kA/m-1,000 kA/m, or about 1 kA/m-1000 kA/m. In
various examples, the average change in yield shear strength or viscosity
per change in the magnetic field can be approximately linear, non-linear,
or a combination thereof. In some embodiments, the average change in
yield shear strength or viscosity is approached, at which point the
relationship can become non-linear; in other embodiments, the
relationship can be approximately linear or non-linear throughout. In
some examples, the average change in viscosity per change in the magnetic
field can be about 0.001-1,000,000 cP per 1 kA/m, or about 0.1-100,000 cP
per 1 kA/m, or about 1-1000 cP per 1 kA/m. In some examples, the average
change in yield shear strength per change in the magnetic field can be
about 0.001-1,000,000 Pa per 1 kA/m, or about 0.1-100,000 Pa per 1 kA/m,
or about 1-1000 Pa per 1 kA/m, or about 50-600 Pa per 1 kA/m. In some
embodiments, the MR fluid can have a maximum yield shear strength or
viscosity; in other embodiments, the MR fluid can have no maximum yield
shear strength or viscosity. In various embodiments, the MR fluid can
have a maximum yield shear strength of about 0.001 kPa, 0.01 kPa, 0.1
kPa, 1 kPa, 2 kPa, 3 kPa, 4 kPa, 5 kPa, 10 kPa, 20 kPa, 30 kPa, 40 kPa,
50 kPa, 75 kPa, 100 kPa, 150 kPa, 200 kPa, 300 kPa, 400 kPa, 500 kPa, 750
kPa, 1000 kPa, 10,000 kPa, 100,000 kPa, or about 1,000,000 kPa or more.
In various embodiments, the MR fluid can have a maximum viscosity at
about room temperature of about 0.01 cP, 0.1 cP, 1 cP, 5 cP, 10 cP, 15
cP, 20 cP, 50 cP, 100 cP, 200 cP, 500 cP, 1000 cP, 5000 cP, 10,000 cP,
50,000 cP, 100,000 cP, 500,000 cP, 1,000,000 cP, 10,000,000 cP,
100,000,000 cP, 500,000,000 cP, or about 1,000,000,000 cP or more.

[0018] An alternating magnetic field may be applied by the one or more
magnetic probes. The magnetic field is alternated at a rate of
approximately 50 kHz to approximately 10 MHz. The magnetic field has a
strength of approximately 10 mT to approximately 250 mT. The magnetic
field may penetrate a formation to a depth of approximately 2 m to
approximately 10 m. In various examples, the current applied to the
electromagnet generates a magnetic field at the location where the
viscosity, yield shear strength, or combination thereof of the fluid is
altered by any suitable strength, such as about 0.01 kA/m-100,000 kA/m,
0.1 kA/m-1,000 kA/m, or about 1 kA/m-1000 kA/m.

[0019] Magnetic nanoparticles can be induced to produce heat when subject
to an alternating magnetic field. This heat may in turn be used to heat
the formation. The initial temperature of a formation may be, for
example, approximately 32° F. to approximately 250° F. A
fracture fluid may be introduced at a temperature of approximately
70° F. to approximately 450° F. The temperature of the
formation may initially drop after introduction of the fracture fluid to
approximately 100° F. The temperature of the oil shale formation
may be increased by approximately -200° F. to approximately
600° F., or by approximately 300° F. to approximately
400° F. The heating using the in-situ conversion process may raise
the temperature of the formation to a predetermined temperature of
approximately 500° F. to approximately 750° F. Time to
raise the temperature to the predetermined temperature may be
approximately 1 hour to approximately 1 month. The in-situ conversion
process may be operated at the predetermined temperature for
approximately 2 years to approximately 7 years. Generated heat may be
utilized in thermal cracking of kerogen or other heavy hydrocarbons into
low molecular weight hydrocarbons, gas and/or water molecules. Shale oil
produced by the in-situ conversion process may result in lighter crude
oils, such as 25-40° API or heavier crude oils, such as 20°
API or less. Hydrocarbons created by the in-situ conversion process may
be produced by conventional methodology. Primary production may utilize
the reservoir pressure and increase in pressure due to the fluid
expansion. The hydraulic fracturing can be used to increase communication
in the reservoir. Gas injection is another method that can be utilize in
pressure maintenance during the oil production.

[0020] In certain embodiments, the formation may contain primarily kerogen
in addition to inorganic material, such as the Green River Formation.
Kerogen may be converted into bitumen and lighter oils by heating. Oil
types may be determined by API gravity and viscosity. API gravities and
approximate viscosity values for different types of oils are listed below
in Table 1.

[0021] Exemplary compositions for fracture fluids are also described
herein. The exemplary fracture fluids may incorporate magnetic
nanoparticles with a fracture fluid base. An exemplary formulation may
include one or more of a fracturing fluid base, a proppant, a thickener,
a crosslinker, a pH adjusting compound, and a breaker.

[0022] Magnetic nanoparticles may be added to the fracture fluid
formulation. The magnetic nanoparticles may be one or more of iron
(II,III) oxide (Fe3O4), magnetic cores including metals (for
example, but not limited to, nickel, cobalt and neogymium-iron-boron),
and others. The nanoparticles may have a concentration of approximately
0.1 lb/bbl to approximately 100 lb/bbl, more preferably a concentration
of approximately 0.15 lb/bbl to approximately 50 lb/bbl and most
preferably a concentration of approximately 0.2 lb/bbl to approximately
10 lb/bbl. To aid in suspension of the magnetic nanoparticles, the
magnetic nanoparticles may have a specific gravity of approximately
0.8-1.2.

[0023] The fracture fluid ingredients may be compatible with the magnetic
nanoparticles and vice versa. For example, it may be desirable that the
magnetic nanoparticles do not react with metallic or other crosslinkers.
The magnetic nanoparticles should also be processed in a way to maintain
a desired nano-size dispersion. For example, a dispersing agent may be
used, and/or the formulation may be slow mixed at the beginning or end of
a batch process, and/or magnetic nanoparticles may be added on the fly
during the job to create a desired nano-size dispersion. To determine
desirable nanoparticles, a fixed percentage or approximately 0.1-30%
magnetic nanoparticles may be added to a fracturing fluid, such as a
standard water plus gel fluid. An electric field applied while in a
magnetic strength measuring tester or chamber may allow for rank ordering
performance responses of different sizes and chemistries of the
nanoparticles.

[0024] Embodiments may produce hydrocarbons that are more profitable than
the original hydrocarbons, and may have a lower environmental impact than
ex-situ recovery techniques, particularly for the Green River Formation.
Higher oil prices and higher demand for oil may make this type of
technology more commercially viable. Increasing oil production from
unconventional resources may also foster energy independence. Embodiments
may also be used to recover heavy oil by decreasing the viscosity of
bitumen to a lower recoverable viscosity. Because some embodiments may
have a permanent magnetic moment or quality, some of the nanoparticles
can be recovered from the well using the nanoparticles' magnetic
properties. In certain embodiments, the magnetic nanoparticles may assist
the fracking ability of the combined composition. Certain sized particles
may attach to and harden proppant to resist fracture reclosure, for
example.

[0025] The in-situ conversion process described herein may be used in
combination with other recovery processes. Magnetic nanoparticles may
have additional functionality. Additional functionalities may include,
but are not limited to, catalytic functionality, increasing yield
strength, increasing suspension ability (gel strength) for proppant
holdings, and/or delaying sinking of proppant in a fracture zone.

[0026] All numbers and ranges disclosed above may vary by some amount.
Whenever a numerical range with a lower limit and an upper limit is
disclosed, any number and any included range falling within the range is
specifically disclosed. In particular, every range of values (of the
form, "from about a to about b," or, equivalently, "from approximately a
to b," or, equivalently, "from approximately a-b") disclosed herein is to
be understood to set forth every number and range encompassed within the
broader range of values.

[0027] Although the foregoing description is directed to the preferred
embodiments of the disclosure, it is noted that other variations and
modifications will be apparent to those skilled in the art, and may be
made without departing from the spirit or scope of the disclosure.
Moreover, features described in connection with one embodiment of the
disclosure may be used in conjunction with other embodiments, even if not
explicitly stated above.